Epoxidized fatty acid methyl ester as low-shear rheology modifier for invert emulsion oil based mud

ABSTRACT

An invert oil-based mud (OBM) may include an oleaginous continuous phase, an aqueous internal phase, an emulsifier; and a rheology modifier. The rheology modifier may include one or more of the group consisting of epoxidized methyl oleate, epoxidized methyl linoleate, and epoxidized methyl α-linolenate. The invert OBM may contain the rheology modifier in an amount of the range of 0.1 to 5 wt. % (weight percent) relative to the total weight of the OBM.

BACKGROUND

Wellbore drilling operations may use wellbore fluids for multiplepurposes including, for example, cooling the drill bit and transportingwellbore cuttings to the surface. Drilling fluids are also used toreduce friction between the drill string and the casing or the wellborewall by functioning as a lubricating medium. Drilling fluids can bedivided into a variety of categories including, for example, oil-baseddrilling fluids and water-based drilling fluids. Additives may beincluded to enhance the properties of the fluids.

Although water-based muds (WBMs) are often preferred due toenvironmental concerns that are associated with oil-based muds (OBMs),they may not be viable for use in certain high pressure and hightemperature (HPHT) sections of a wellbore. This leads to the employmentof OBMs, including invert emulsion OBMs, which may be more stable undersuch conditions. OBMs can also provide improved shale inhibition ascompared to WBMs, and so are also preferred when drilling wellboresections that contain reactive shale. Invert emulsion OBMs may beformulated to include additives, such as emulsifiers, which aid in theformation of a stable water-in-oil (W/O) emulsion, and rheologymodifiers, which allow for tuning the rheological properties of thefluid.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments disclosed relate to an invert oil-based mud(OBM) that includes an oleaginous continuous phase, an aqueous internalphase, an emulsifier; and a rheology modifier. The rheology modifier mayinclude one or more of the group consisting of epoxidized methyl oleate,epoxidized methyl linoleate, and epoxidized methyl α-linolenate.

In another aspect, embodiments disclosed relate to methods of using aninvert oil-based mud (OBM) in a wellbore that include introducing theinvert OBM into the wellbore. The invert OBM may include an oleaginouscontinuous phase; an aqueous internal phase; an emulsifier; and arheology modifier. The rheology modifier may include one or moreselected from the group consisting of epoxidized methyl oleate,epoxidized methyl linoleate, and epoxidized methyl alpha-linolenate.

In a further aspect, embodiments disclosed relate to methods ofpreparing an invert oil-based mud (OBM), the methods including forming arheology modifier by epoxidizing linseed oil and transesterifying theepoxidized linseed oil with methanol, and mixing the rheology modifierwith an emulsifier, an oleaginous phase, and an aqueous phase.

Other aspects and advantages of the claimed subject matter will beapparent from the description, the drawings, and the claims that follow.

BRIEF DESCRIPTION OF DRAWINGS

FIGS. 1A-B depict the chemical structures of an epoxidized triglyceride(FIG. 1A) and epoxidized fatty acid methyl esters (FIG. 1B) of one ormore embodiments, which are derived from linseed oil.

FIG. 2 is a schematic representation of a method of producing an invertemulsion OBM of one or more embodiments.

FIG. 3 is a graphical representation of the low-shear rheology ofexemplary wellbore fluids.

FIG. 4 is a graphical representation of the 10 second and 10 minute gelstrength of exemplary wellbore fluids.

DETAILED DESCRIPTION

Embodiments in accordance with the present disclosure generally relateto rheology modifiers and their preparation, wellbore fluids thatcontain said rheology modifiers, and methods of using said wellborefluids. Generally, the rheology modifiers of one or more embodimentsdisclosed comprise one or more epoxidized fatty acid esters.

The suitability of a wellbore fluid for its use in a given applicationis significantly determined by its rheological properties, including itsplastic viscosity, gel strength, yield point, and low shear raterheology. These properties may be altered by the inclusion of rheologymodifiers. Rheology modifiers are of particular importance in drillingfluids because the low-shear rheology of the fluid is directly relevantin determining the ability of the fluid to suspend solids, such asweighting materials and drill cuttings, enabling their removal from thewellbore.

Rheology Modifiers

Rheology modifiers in accordance with one or more embodiments of thepresent disclosure comprise one or more epoxidized fatty acid esters.These epoxidized fatty acid esters may be derived from a vegetable oil.The vegetable oil of some embodiments may be a triglyceride extractedfrom a plant. A triglyceride is an ester of glycerol and three fattyacids. Depending on the plant from which it is derived, a vegetable oilmay contain a mixture of different types of fatty acids, including, forexample, saturated, mono unsaturated, poly unsaturated, omega 3, omega6, and omega 9 fatty acids. The presence of these different types offatty acids makes vegetables a promising source for rheology modifiersfor drilling fluids. In some embodiments, the rheology modifiers of thepresent disclosure may be derived from unused or unprocessed vegetableoils, such as virgin, fresh, or raw oils. In other embodiments, therheology modifiers of the present disclosure may be derived from wastevegetable oils that have been used for a different process, such ascooking or other food preparations, prior to the preparation of therheology modifier.

Rheology modifiers in accordance with one or more embodiments of thepresent disclosure may contain epoxidized fatty acid esters that arederived from linseed oil. Linseed oil (which is also commonly known asflaxseed oil) is a natural oil that is derived from the seeds of theflax plant. It is widely used as an impregnator for various materials,as a drying oil or varnish, as a pigment binder, as a plasticizer, andas a nutritional supplement. Linseed oil comprises a triglyceridecontaining three different unsaturated fatty acids, namely oleic,linoleic acid and α-linolenic acid. Linseed oil may further containsmaller amounts of saturated fatty acids such as palmitic acid andstearic acid in addition to one or more unsaturated fatty acids.

The rheology modifier of one or more embodiments particularly comprisesone or more epoxidized fatty acid esters. These epoxidized fatty acidesters may be prepared by first epoxidizing an unsaturated triglycerideto give an epoxidized triglyceride. Where, for instance, thetriglyceride is linseed oil, the resulting epoxidized triglyceride maybe epoxidized linseed oil as depicted in FIG. 1A. The epoxidizedtriglyceride may contain fatty acids having a carbon chain ranging inlength from C6 to C32. For example, the epoxidized triglyceride maycontain fatty acids having a carbon chain having a length ranging from alower limit of any of 6, 8, 10, 12, 14, 16, and 18 carbons to an upperlimit of any of 18, 20, 22, 24, 26, 28, 30, and 32 carbons, where anylower limit can be used in combination with anymathematically-compatible upper limit. Transesterifying the epoxidizedtriglyceride by reaction with an alcohol yields the correspondingepoxidized fatty acid esters. The particular alcohol used for thetransesterification may not be particularly limited. In someembodiments, the alcohol may be one or more selected from the groupconsisting of methanol, ethanol, propanol, butanol, petanol, and isomersand derivatives thereof. In particular embodiments, the alcohol may bemethanol, and the resulting epoxidized fatty acid esters may beepoxidized fatty acid methyl esters (“EME-FA”).

In embodiments where the triglyceride is linseed oil and the alcohol ismethanol, the resulting rheology modifier will comprise the epoxidizedmethyl ester of oleic acid (also known as epoxidized methyl oleate), theepoxidized methyl ester of linoleic acid (also known as epoxidizedmethyl linoleate), and the epoxidized methyl ester of α-linolenic acid(also known as epoxidized methyl α-linolenate), as depicted in FIG. 1B.In some embodiments, the EME-FA may be a commercial product, such asVIKOFLEX® 9010 (Arkema; King of Prussia, Pa.).

The rheology modifier of one or more embodiments may comprise an esterof oleic acid, an ester of linoleic acid, and an ester of α-linolenicacid. In some embodiments, the rheology modifier may consist essentiallyof an epoxidized ester of oleic acid, an epoxidized ester of linoleicacid, and an epoxidized ester of α-linolenic acid. In some embodiments,the rheology modifier may consist of an epoxidized ester of oleic acid,an epoxidized ester of linoleic acid, and an epoxidized ester ofα-linolenic acid.

In embodiments where the rheology modifier is derived from linseed oil,the rheology modifier may comprise an epoxidized ester of oleic acid, anepoxidized ester of linoleic acid, and an epoxidized ester ofα-linolenic acid, in relative amounts that reflect the content of eachof oleic acid, linoleic acid, and α-linolenic acid in the linseed oil.

The rheology modifier of one or more embodiments may contain anepoxidized ester of oleic acid in an amount of the range of about 1 to30% by weight (wt. %). For example, the rheology modifier may containthe epoxidized ester of oleic acid in an amount ranging from a lowerlimit of any of 1, 2, 5, 10, 12, 15, 18, and 20 wt. % to an upper limitof any of 10, 12, 15, 18, 20, 22, 25, and 30 wt. %, where any lowerlimit can be used in combination with any mathematically-compatibleupper limit.

The rheology modifier of one or more embodiments may contain anepoxidized ester of linoleic acid in an amount of the range of about 1to 30 wt. %. For example, the rheology modifier may contain theepoxidized ester of linoleic acid in an amount ranging from a lowerlimit of any of 1, 2, 5, 10, 12, 15, 18, and 20 wt. % to an upper limitof any of 10, 12, 15, 18, 20, 22, 25, and 30 wt. %, where any lowerlimit can be used in combination with any mathematically-compatibleupper limit.

The rheology modifier of one or more embodiments may contain anepoxidized ester of α-linolenic acid in an amount of the range of about30 to 70 wt. %. For example, the rheology modifier may contain theepoxidized ester of α-linolenic acid in an amount ranging from a lowerlimit of any of 30, 35, 40, 45, 50, 55, and 60 wt. % to an upper limitof any of 40, 45, 50, 55, 60, 65, and 70 wt. %, where any lower limitcan be used in combination with any mathematically-compatible upperlimit.

Wellbore Fluids

One or more embodiments of the present disclosure relate to wellborefluids and may include, for example, water-based wellbore fluids, invertemulsion wellbore fluids, and oil-based wellbore fluids. The wellborefluids may be drilling fluids, such as oil-based drilling muds (OBMs).

Oil-based wellbore fluids of one or more embodiments may have anoleaginous base fluid. The oleaginous fluid may be a natural orsynthetic oil. In one or more embodiments, the oleaginous fluid may beone or more of diesel oil, mineral oil, polyalphaolefins, siloxanes,organosiloxanes, fatty acid esters, and mixtures thereof.

The wellbore fluid of one or more embodiments may comprise a rheologymodifier in an amount ranging from about 0.1 to about 10% by volume(vol. %). For example, the wellbore fluid may contain the rheologymodifier in an amount ranging from a lower limit of any of 0.1, 0.3,0.5, 0.7, 1.0, 1.2, 1.5, 2.0, 2.5, 3.0, and 5.0 vol. % to an upper limitof any of 1.0, 1.5, 2.0, 2.5, 3.0, 3.5, 4.0, 5.0, 7.5, and 10 vol. %,where any lower limit can be used in combination with anymathematically-compatible upper limit. In particular embodiments, thewellbore fluid may contain the rheology modifier in an amount of about1.0 to about 3.0 vol. %.

The wellbore fluid of one or more embodiments may comprise a rheologymodifier in an amount ranging from about 0.1 to about 5 wt. %. Forexample, the wellbore fluid may contain the rheology modifier in anamount ranging from a lower limit of any of 0.1, 0.2, 0.3, 0.4, 0.5,0.6, 0.7, 0.8, 1.0, 1.2, 1.5, 2.0, 2.5, and 3.0 wt. % to an upper limitof any of 0.5, 0.6, 0.8, 1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.5, 3.0, 3.5,4.0, 4.5, and 5.0 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit. Inparticular embodiments, the wellbore fluid may contain the rheologymodifier in an amount of about 0.5 to 1.5 wt. %.

Wellbore fluids of one or more embodiments may be emulsions thatcomprise both an oleaginous external phase and a non-oleaginous internalphase. The oleaginous external phase may comprise one or more of theoleaginous fluids described previously. The non-oleaginous internalphase may be an aqueous fluid. The aqueous fluid may include at leastone of fresh water, synthetic or natural seawater, synthetic or naturalbrine, formation water, production water, brackish water, each of whichmay contain water-soluble organic compounds or minerals, or both, andmixtures thereof. The aqueous fluid may be fresh water that isformulated to contain various salts. The salts may include, but are notlimited to, alkali metal halides and hydroxides. In one or moreembodiments of the wellbore fluid disclosed, the brine may be any ofseawater, aqueous solutions where the salt concentration is less thanthat of sea water, or aqueous solutions where the salt concentration isgreater than that of seawater. Salts that may be found in seawater mayinclude salts that produce disassociated ions of sodium, calcium,aluminium, magnesium, potassium, strontium, and lithium salts ofhalides, carbonates, chlorates, bromates, nitrates, oxides, andphosphates, among others. In some embodiments, the brine may include oneor more of the group consisting of an alkali metal halide, an alkalimetal carboxylate salt, an alkaline earth metal halide, and an alkalineearth metal carboxylate salt. In particular embodiments, the brine maycomprise calcium chloride. Any of the aforementioned salts may beincluded in brine.

In one or more embodiments, the density of aqueous fluid, and, in turn,the wellbore fluid, may be controlled by increasing the saltconcentration. The maximum concentration is determined by the solubilityof the salt.

In some embodiments, wellbore fluids may be invert emulsions that havean oleaginous external phase and a non-oleaginous internal phase. Theinvert emulsion of one or more embodiments may contain a volume ratio ofthe oleaginous phase to the non-oleaginous phase ranging from about30:70 to about 99:1. For example, the invert emulsion may have a volumeratio of the oleaginous phase to the non-oleaginous phase ranging from alower limit of any of 30:70, 40:60, 50:50, 60:40, 70:30, 80:20, and90:10 to an upper limit of any 40:60, 50:50, 60:40, 70:30, 80:20, 90:10,95:5, and 99:1, where any lower limit can be used in combination withany mathematically-compatible upper limit.

In one or more embodiments, wellbore fluids may contain one or moreemulsifiers. A first, or primary, emulsifier may be added to create astable emulsion of water in oil. The primary emulsifier can reduceinterfacial tension between the oleaginous and nonoleaginous phases andincrease the emulsion stability of the drilling fluid. The primaryemulsifier of one or more embodiments is not particularly limited, butmay be a fatty acid derivative such as INVERMUL® (Halliburton; Houston,Tex.).

The wellbore fluid of one or more embodiments may comprise a primaryemulsifier in an amount ranging from about 0.1 to about 20 vol. %. Forexample, the wellbore fluid may contain the primary emulsifier in anamount ranging from a lower limit of any of 0.1, 0.3, 0.5, 0.7, 1.0,1.2, 1.5, 2.0, 2.5, 3.0, 4.0, 5.0, and 10.0 vol. % to an upper limit ofany of 1.0, 2.0, 3.0, 4.0, 5.0, 6.0, 7.0, 10.0, 12.5, 15.0, 17.5, and20.0 vol. %, where any lower limit can be used in combination with anymathematically-compatible upper limit. In particular embodiments, thewellbore fluid may contain the primary emulsifier in an amount of about1.0 to about 6.0 vol. %.

The wellbore fluid of one or more embodiments may comprise a primaryemulsifier in an amount ranging from about 0.1 to about 10 wt. %. Forexample, the wellbore fluid may contain the primary emulsifier in anamount ranging from a lower limit of any of 0.1, 0.3, 0.5, 0.7, 1.0,1.2, 1.5, 2.0, 2.5, 3.0, and 5.0 wt. % to an upper limit of any of 1.0,1.5, 2.0, 2.5, 3.0, 3.5, 4.0, 5.0, 7.5, and 10 wt. %, where any lowerlimit can be used in combination with any mathematically-compatibleupper limit. In particular embodiments, the wellbore fluid may containthe primary emulsifier in an amount of about 1.0 to about 3.0 wt. %.

In one or more embodiments, wellbore fluids may contain an additional,or secondary, emulsifier. The secondary emulsifier may be utilized toconsolidate the stability of the dispersed phase or the overallemulsion. The secondary emulsifier of one or more embodiments is notparticularly limited but, as would be understood by a person of ordinaryskill in the art, is generally selected to be compatible with theprimary emulsifier. In some embodiments, the secondary emulsifier may beEZ MUL® (Halliburton; Houston, Tex.).

The wellbore fluid of one or more embodiments may comprise a secondaryemulsifier in an amount ranging from about 0.1 to about 10% by volume(vol. %). For example, the wellbore fluid may contain the secondaryemulsifier in an amount ranging from a lower limit of any of 0.1, 0.3,0.5, 0.7, 1.0, 1.2, 1.5, 2.0, 2.5, 3.0, and 5.0 vol. % to an upper limitof any of 1.0, 1.5, 2.0, 2.5, 3.0, 3.5, 4.0, 5.0, 7.5, and 10 vol. %,where any lower limit can be used in combination with anymathematically-compatible upper limit. In particular embodiments, thewellbore fluid may contain the secondary emulsifier in an amount ofabout 0.5 to about 2.0 vol. %.

The wellbore fluid of one or more embodiments may comprise a secondaryemulsifier in an amount ranging from about 0.1 to about 5 wt. %. Forexample, the wellbore fluid may contain the secondary emulsifier in anamount ranging from a lower limit of any of 0.1, 0.2, 0.3, 0.4, 0.5,0.6, 0.7, 0.8, 1.0, 1.2, 1.5, 2.0, 2.5, and 3.0 wt. % to an upper limitof any of 0.5, 0.6, 0.8, 1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.5, 3.0, 3.5,4.0, 4.5, and 5.0 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit. Inparticular embodiments, the wellbore fluid may contain the secondaryemulsifier in an amount of about 0.1 to about 1.0 wt. %.

Further, other additives may be included in the wellbore fluids of thepresent disclosure. Such additives may include, for instance, one ormore of the group consisting of weighting agents, pH adjusting agents,additional rheology modifiers (or viscosifiers), wetting agents,corrosion inhibitors, oxygen scavengers, anti-oxidants, biocides,surfactants, dispersants, interfacial tension reducers, mutual solvents,thinning agents, and combinations thereof. The identities and use of theaforementioned additives are not particularly limited. One of ordinaryskill in the art will, with the benefit of this disclosure, appreciatethat the inclusion of a particular additive will depend upon the desiredapplication, and properties, of a given wellbore fluid.

Weighting agents suitable for use in the wellbore fluids of one or moreembodiments include, for example, bentonite, barite, dolomite, calcite,aragonite, iron carbonate, zinc carbonate, manganese tetroxide, zincoxide, zirconium oxide hematite, ilmenite, lead carbonate, andcombinations thereof.

The pH adjusting agents that are included in the wellbore fluids of oneor more embodiments may be one or more alkaline compounds. In one ormore embodiments, suitable alkaline compounds include alkali metal andalkaline metal salts such as, lime, soda ash, sodium hydroxide,potassium hydroxide, and combinations thereof.

The wellbore fluid of one or more embodiments may comprise a pHadjusting agent in an amount ranging from about 0.1 to about 5 wt. %.For example, the wellbore fluid may contain the pH adjusting agent in anamount ranging from a lower limit of any of 0.1, 0.2, 0.3, 0.4, 0.5,0.6, 0.7, 0.8, 1.0, 1.2, 1.5, 2.0, 2.5, and 3.0 wt. % to an upper limitof any of 0.5, 0.6, 0.8, 1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.5, 3.0, 3.5,4.0, 4.5, and 5.0 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit. Inparticular embodiments, the wellbore fluid may contain the pH adjustingagent in an amount of about 0.5 to about 1.5 wt. %.

The viscosifiers that are included in the wellbore fluids of one or moreembodiments may be selected from the group consisting of organophilicclays, hectorite clays, dimeric and trimeric fatty acids, polyamines,and sepiolite. In some embodiments, the viscosifier may be GELTONE® II(Halliburton; Houston, Tex.).

The wellbore fluid of one or more embodiments may comprise a viscosifierin an amount ranging from about 0.1 to about 5 wt. %. For example, thewellbore fluid may contain the viscosifier in an amount ranging from alower limit of any of 0.1, 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8, 1.0, 1.2,1.5, 2.0, 2.5, and 3.0 wt. % to an upper limit of any of 0.5, 0.6, 0.8,1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.5, 3.0, 3.5, 4.0, 4.5, and 5.0 wt. %,where any lower limit can be used in combination with anymathematically-compatible upper limit. In particular embodiments, thewellbore fluid may contain the viscosifier in an amount of about 0.1 toabout 1.0 wt. %.

The filtration control agents that are included in the wellbore fluidsof one or more embodiments may be selected from the group consisting ofmodified lignites, asphalts or gilsonites, and nonaqueous polymericfluids. In some embodiments, the filtration control agent may beDURATONE® HT (Halliburton; Houston, Tex.)

The wellbore fluid of one or more embodiments may comprise a filtrationcontrol agent in an amount ranging from about 0.1 to about 5 wt. %. Forexample, the wellbore fluid may contain the filtration control agent inan amount ranging from a lower limit of any of 0.1, 0.2, 0.3, 0.4, 0.5,0.6, 0.7, 0.8, 1.0, 1.2, 1.5, 2.0, 2.5, and 3.0 wt. % to an upper limitof any of 0.5, 0.6, 0.8, 1.0, 1.2, 1.4, 1.6, 1.8, 2.0, 2.5, 3.0, 3.5,4.0, 4.5, and 5.0 wt. %, where any lower limit can be used incombination with any mathematically-compatible upper limit. Inparticular embodiments, the wellbore fluid may contain the filtrationcontrol agent in an amount of about 0.5 to about 1.5 wt. %.

A method of preparing an invert OBM of one or more embodiments isdepicted by FIG. 2. All components and quantities discussed in relationto said method correspond to those discussed previously. At 200, arheology modifier is prepared from a vegetable oil. For example, therheology modifier may be prepared from linseed oil as discussedpreviously. In one or more embodiments, the rheology modifier maycomprise one or more epoxidized fatty acid esters, such as an ester ofepoxidized oleic acid, an ester of epoxidized linoleic acid, and anester of epoxidized α-linolenic acid.

At 210, a quantity of the rheology modifier and a quantity of one ormore emulsifiers are added to an oleaginous base fluid. At 220, aquantity of an optional additive, such as a pH adjusting agent, may alsobe added to the oleaginous base fluid. At 230, a quantity of anonoleaginous fluid is added to the oleaginous fluid to which thepreviously mentioned components have been added. At 240, a quantity ofan additive, such as a weighting agent is added to the aforementionedcomponents. At 250, the inverted oil-based drilling fluid mixed with thepreviously mentioned components is used in a wellbore drilling operationto drill a wellbore in a subterranean zone. For example, multiplebarrels of the oil-based drilling fluid are prepared, each barrel mixedwith the previously-mentioned components. The multiple barrels areflowed through a subterranean zone while drilling a wellbore in thesubterranean zone.

The physical properties of a wellbore fluid are important in determiningthe suitability of the fluid for a given application.

The wellbore fluid of one or more embodiments may have a density that isgreater than 60 lb/ft³ (pounds per cubic foot). For example, thewellbore fluid may have a density that is of an amount ranging from alower limit of any of 60, 62, 64, 66, 68, 70, 75, and 80 lb/ft³ to anupper limit of any of 66, 70, 80, 90, 100, 110, 120, 130, 140, 150 and160 lb/ft³, where any lower limit can be used in combination with anymathematically-compatible upper limit.

Rheological features such as plastic viscosity (PV), yield point (YP),initial gel strength, and final gel strength can be determined for awellbore fluid. The values described may be determined for a wellborefluid after hot-rolling at, for instance, 300° F. for 16 h (hours) undera pressure of 500 psi (pounds per square inch). The values were obtainedfrom a viscometer at dial readings of 600 rpm (revolutions per minute)and 300 rpm. To measure the initial and final gel strength of a wellborefluid, a viscometer can be operated at 600 rpm for 10 s (seconds) andthen switched off for 10 s and 10 min (minutes), respectively.Afterward, the viscometer can be turned to a revolution speed of 3 rpmto provide the gel strength reading.

The YP and PV are parameters from the Bingham Plastic rheology (BP)model. The plastic viscosity of a fluid is a measure of the resistanceof the fluid to flow. For instance, drilling fluids that have a reducedplastic viscosity have the capacity to drill more quickly than drillingfluids with a greater PV value. Plastic viscosity is dependent on boththe solid content of a fluid and temperature. The wellbore fluid of oneor more embodiments may have a plastic viscosity ranging from about 1 to40 cP (centipoise). For example, the wellbore fluid may have a plasticviscosity that ranges from a lower limit of any of 1, 5, 10, 15, 20, 25,and 30 cP to an upper limit of any of 20, 25, 30, 35, and 40 cP, whereany lower limit can be used in combination with anymathematically-compatible upper limit.

The YP is determined by extrapolating the BP model to a shear rate ofzero; it represents the stress required to move the fluid. The yieldpoint is the resistance of a fluid to initiate movement and is anassessment of the strength of the attractive forces between thecolloidal particles of the fluid. The yield point, for instance,demonstrates the capability of a drilling fluid to raise shale cuttingsout of a wellbore under dynamic conditions. A fluid with a greater yieldpoint may provide a better carrying capacity as compared to a fluid withsimilar density and a reduced yield point. The wellbore fluid of one ormore embodiments may have a yield point ranging from about 5 to 15lb/100 ft² (pounds per 100 square feet). For example, the wellbore fluidmay have a yield point that ranges from a lower limit of any of 5, 6, 7,8, 9, and 10 lb/100 ft² to an upper limit of any of 10, 11, 12, 13, 14,and 15 lb/100 ft², where any lower limit can be used in combination withany mathematically-compatible upper limit.

The wellbore fluid of one or more embodiments may have an initial gelstrength, after 10 seconds, ranging from about 5 to about 20 lb/100 ft².For example, the wellbore fluid may have an initial gel strength thatranges from a lower limit of any of 5, 6, 7, 8, 9, and 10 lb/100 ft² toan upper limit of any of 9, 10, 12, 15, and 20 lb/100 ft², where anylower limit can be used in combination with anymathematically-compatible upper limit.

The wellbore fluid of one or more embodiments may have a final gelstrength, after 10 minutes, ranging from about 5 to about 30 lb/100 ft².For example, the wellbore fluid may have a final gel strength thatranges from a lower limit of any of 5, 7, 9, 10, 11, 12, 13, 15, and 20lb/100 ft² to an upper limit of any of 13, 15, 18, 20, 25, and 30 lb/100ft², where any lower limit can be used in combination with anymathematically-compatible upper limit.

The wellbore fluid of one or more embodiments may have a 3-rpmviscometer reading ranging from about 1 to about 15 cP. For example, thewellbore fluid may have a plastic viscosity that ranges from a lowerlimit of any of 1, 2, 3, 4, 5, 6, and 8 cP to an upper limit of any of6, 8, 10, 12, and 15 cP, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The wellbore fluid of one or more embodiments may have a 6-rpmviscometer reading ranging from about 5 to about 20 cP. For example, thewellbore fluid may have a plastic viscosity that ranges from a lowerlimit of any of 5, 6, 7, 8, 9 and 10 cP to an upper limit of any of 7,8, 9, 10, 12, 15, and 20 cP, where any lower limit can be used incombination with any mathematically-compatible upper limit.

The apparent viscosity of a fluid is directly related to the swellingrate of the fluid in the presence of an inhibition medium. Therefore, alow apparent viscosity demonstrates that the fluid may have a reducedinteraction with clay. The wellbore fluid of one or more embodiments mayhave an apparent viscosity ranging from about 10 to about 150 cP. Forexample, the wellbore fluid may have an apparent viscosity that rangesfrom a lower limit of any of 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60,65, 70, 75, 80, 90 and 100 cP to an upper limit of any of 20, 30, 40,50, 60, 70, 80, 90, 100, 110, 120, 130, 140, and 150 cP, where any lowerlimit can be used in combination with any mathematically-compatibleupper limit.

Methods

Wellbore fluids of one or more embodiments may be introduced into awellbore or subterranean formation using techniques known to a person ofordinary skill in the art. The wellbore fluids of one or moreembodiments may be used as one or more of a drilling or drill-in fluidduring the drilling of a wellbore. The oil-based drilling fluid mixedwith the previously mentioned components may be used in a wellboredrilling operation to drill a wellbore in a subterranean zone. Forexample, multiple barrels of the oil-based drilling fluid may beprepared, each barrel mixed with the previously discussed components.The multiple barrels are introduced into a subterranean zone whiledrilling the wellbore in the subterranean zone.

Examples

The following examples are merely illustrative and should not beinterpreted as limiting the scope of the present disclosure.

Materials and Synthesis:

The fatty acid methyl esters (hereafter “EME-FA”) used in these exampleswas VIKOFLEX® 9010 (Arkema), which contains epoxidized methyl oleate,epoxidized methyl linoleate, and epoxidized methyl alpha-linoleate.

In order to ascertain the ability of the EME-FA to function as arheology modifier, invert OBMs having the compositions detailed in Table1 were prepared. In the examples, 12 ppb (pounds per barrel) of theprimary emulsifiers are used to formulate 80 pcf (per cubic feet)invert-emulsion oil based muds using Safra-oil as a base oil. Safra oilis a highly de-aromatized aliphatic solvent in the class of kerosene.The oil-water ratio is 70:30 by volume. “mL” means millilitres and “g”means grams.

TABLE 1 Compositions of exemplary drilling muds Formulation Example 1Comparative Example 1 Safra oil (mL) 218 218 INVERMUL ® (mL) 12 12 EZMUL ® (mL) 4 4 Lime (g) 6 6 GELTONE ® (g) 4 4 DURATONE ® (g) 6 6 Brine(mL) (61 g CaCl₂ 85 85 in 85 mL of water) Barite (g) 161 161 EME-FA (mL)6 0

Characterization:

The OBM dispersions were hot rolled at 300° F. for 16 h under a pressureof 500 psi. After hot rolling, the OBMs were cooled to room temperatureand a OFITE Model 900 viscometer (OFI Testing Equipment, Inc.) wasutilized for testing their rheology. The rheological properties ofExample 1 and Comparative Example 1 were measured at 49° C. and arereported in Table 2.

TABLE 2 Rheological properties of exemplary OBMs Property Example 1Comparative Example 1 Plastic viscosity (PV) (cP) 31 22.9 Yield point(YP) (lb/100 ft²) 10.3 9.2 6-rpm reading (cP) 8.8 4.1 3-rpm reading (cP)6.4 3.6 10 sec gel strength (lb/100 ft²) 9.1 5.2 10 min gel strength(lb/100 ft²) 13 10.8

The rheological features such as the plastic viscosity (PV) and yieldpoint (YP) were estimated by using the values obtained from the dialreadings of the viscometer at 600 rpm and 300 rpm. To measure the10-second (initial) gel strength and the 10-minute (final) gel strengthof the OBMs, the viscometer was operated at 600 rpm for 10 s and thenstopped for 10 s and 10 min, respectively. Afterward, the viscometeroperated at a revolution speed of 3 rpm and the dial reading was notedas the 10-sec and 10-min gel strength, respectively, in pounds per 100ft².

Results and Discussion

The plastic viscosity and yield point are important properties thatinform the suitability of an OBM for a given application. Table 2indicates that the yield point of a drilling mud significantly increaseafter addition of the EME-FA and hot rolling at high temperature andpressure. This increased yield point indicates that Example 1 has animproved carrying capacity of cuttings as compared to ComparativeExample 1. The inclusion of EME-FA only resulted in a small increase inplastic viscosity.

The low shear rheology of a drilling mud reflects its ability to suspenda solid material under while the shear is minimized or ceased. Therheology of Example 1 and Comparative Example 1 at 3-rpm and 6-rpm isreported in Table 2 and depicted in FIG. 3, which demonstrate that theaddition of the EME-FA prominently enhances the low shear rheology of anOBM, as compared to a traditional drilling mud. Therefore, the additionof EME-FA provides an OBM having an enhanced solids-suspending capacity.

Similarly, the gel strength of a drilling mud reflects its ability tosuspend a solid material under static conditions. It is a quantificationof the attractive forces within the drilling mud system in the absenceof flow. The gel strength of Example 1 and Comparative Example 1 isreported in Table 2 and depicted in FIG. 4, which demonstrate that theaddition of the EME-FA prominently enhances the gel strength of an OBMafter both 10 s and 10 min, as compared to a traditional drilling mud.Therefore, the addition of EME-FA provides an OBM having an enhancedsolids-suspending capacity.

When either words “approximately” or “about” are used, this term maymean that there can be a variance in value of up to ±10%, of up to 5%,of up to 2%, of up to 1%, of up to 0.5%, of up to 0.1%, or up to 0.01%.

Although the preceding description has been described herein withreference to particular means, materials and embodiments, it is notintended to be limited to the particulars disclosed herein; rather, itextends to all functionally equivalent structures, methods and uses,such as those within the scope of the appended claims.

What is claimed is:
 1. An invert oil-based mud (OBM), comprising: anoleaginous continuous phase; an aqueous internal phase; an emulsifier;and a rheology modifier that comprises one or more of the groupconsisting of epoxidized methyl oleate, epoxidized methyl linoleate, andepoxidized methyl α-linolenate.
 2. The invert OBM according to claim 1,wherein the rheology modifier comprises epoxidized methyl oleate,epoxidized methyl linoleate, and epoxidized methyl α-linolenate.
 3. Theinvert OBM according to claim 1, wherein the invert OBM contains therheology modifier in an amount of the range of 0.1 to 5 wt. % (weightpercent), relative to the total weight of the OBM.
 4. The invert OBMaccording to claim 1, wherein the invert OBM has a plastic viscosity ofthe range of 20 to 40 cP (centipoise).
 5. The invert OBM according toclaim 1, wherein the invert OBM has a yield point of the range of 5 to15 lb/100 ft² (pounds per 100 square feet).
 6. The invert OBM accordingto claim 1, wherein the invert OBM has an initial gel strength after 10seconds of the range of 5 to 15 lb/100 ft².
 7. The invert OBM accordingto claim 1, wherein the invert OBM has a final gel strength after 10minutes of the range of 10 to 20 lb/100 ft².
 8. A method of using aninvert oil-based mud (OBM) in a wellbore, comprising: introducing theinvert OBM into the wellbore, the invert OBM comprising an oleaginouscontinuous phase; an aqueous internal phase; an emulsifier; and arheology modifier that comprises one or more selected from the groupconsisting of epoxidized methyl oleate, epoxidized methyl linoleate, andepoxidized methyl alpha-linolenate.
 9. The method according to claim 8,wherein the emulsifier comprises epoxidized methyl oleate, epoxidizedmethyl linoleate, and epoxidized methyl α-linolenate.
 10. The methodaccording to claim 8, wherein the invert OBM contains the rheologymodifier in an amount of the range of 0.1 to 5 wt. %, relative to thetotal weight of the OBM.
 11. The method according to claim 8, whereinthe invert OBM has a plastic viscosity of the range of 20 to 40 cP. 12.The method according to claim 8, wherein the invert OBM has a yieldpoint of the range of 5 to 15 lb/100 ft².
 13. The method according toclaim 8, wherein the invert OBM has an initial gel strength after 10seconds of the range of 5 to 15 lb/100 ft².
 14. The method according toclaim 8, wherein the invert OBM has a final gel strength after 10minutes of the range of 10 to 20 lb/100 ft².
 15. A method of preparingan invert oil-based mud (OBM), comprising: forming a rheology modifierby epoxidizing linseed oil and transesterifying the epoxidized linseedoil with methanol; and mixing the rheology modifier with an emulsifier,an oleaginous phase, and an aqueous phase.
 16. The method according toclaim 15, wherein the rheology modifier comprises one or more selectedfrom the group consisting of epoxidized methyl oleate, epoxidized methyllinoleate, and epoxidized methyl α-linolenate.
 17. The method accordingto claim 16, wherein the rheology modifier comprises epoxidized methyloleate, epoxidized methyl linoleate, and epoxidized methyl α-linolenate.18. The method according to claim 15, wherein the rheology modifier ismixed in an amount such that the invert OBM contains the rheologymodifier in an amount of the range of 0.1 to 5 wt. %, relative to thetotal weight of the OBM.